In a staged frac operation, multiple zones of a formation need to be isolated sequentially for treatment. To achieve this, operators install a frac assembly 20 as shown in FIG. 1 at the wellbore 10. Typically, the assembly 20 has a top liner packer (not shown) supporting a tubing string 12 in the wellbore 10. Packers 50 isolate the wellbore into zones 14, and various sliding sleeves 40 on the tubing string 12 can selectively communicate the tubing string 12 with the various zones 14. When the zones 14 do not need to be closed after opening, operators may use single shot sliding sleeves 40 for the frac treatment. These types of sleeves 40 are usually ball-actuated and lock open once actuated. Another type of sleeve 40 is also ball-actuated, but can be shifted closed after opening.
Initially, all of the sliding sleeves 40 are closed. Operators then deploy a setting ball to close a wellbore isolation valve (not shown), which seals off the downhole end of the tubing string 12. At this point, the packers 50 are hydraulically set by pumping fluid with a pump system 35 connected to the wellbore's rig 30. The tubing pressure in the tubing string 12 actuates the packers 50 to isolate the annulus into the multiple zones 14. With the packers 50 set, operators rig up fracturing surface equipment and pump fluid down the tubing string 12 to open a pressure actuated sleeve (not shown) further downhole so a first zone 14 can be treated.
As the operation continues, operators drop successively larger balls down the tubing string 14 to open successive sleeves 40 and pump fluid to treat the separate zones 14 in stages. When a dropped ball meets its matching seat in a sliding sleeve 40, fluid is pumped by the pump system 35 down the tubing string 12 and forced against the seated ball. The pumped fluid forced against the seated ball shifts the sleeve 40 open. In turn, the seated ball diverts the pumped fluid out ports in the sleeve 40 to the surrounding wellbore 10 between packers 50 and into the adjacent zone 14 and prevents the fluid from passing to lower zones 14. By dropping successively increasing sized balls to actuate corresponding sleeves 40, operators can accurately treat each zone 14 up the wellbore 10.
FIGS. 2A-2B show two examples of hydraulically set, open hole packers 50A-50B according to the prior art. Looking first at FIG. 2A, the packer 50A has a mandrel 52 with an internal bore 53 passing therethrough that connects on a tubing string (12: FIG. 1). Ends of the mandrel 52 have end rings 56 and 58 disposed externally thereon, and the internal bore 53 of the mandrel 52 has flow ports 54a, 54b for communicating fluid outside the mandrel 52.
A piston 60 disposed externally on the mandrel 52 has a ratchet mechanism 66, such as a body lock ring, on one end for locking movement of the piston 60. The other end 61 of the piston 60 compresses the packing element 70 against the fixed end ring 58 on the mandrel 52 when the piston 60 is actuated.
To actuate the packer 50A hydraulically, fluid communicated down the mandrel's bore 53 enters a piston chamber 64a between the inside of the piston 60 and the mandrel 52 via a flow port 54a. The buildup of tubing pressure inside the chamber 64a slides the piston 60 along the mandrel 52 and forces the piston's end 61 against the packing element 70, which extends outward toward the surrounding borehole wall 15 when compressed.
As the piston chamber 64a increases in volume with the movement of the piston 60, the ratchet mechanism 66 locks against a serrated surface on the mandrel 52 and prevents reverse motion of the piston 60. Additionally, a volume 62 between the piston 60 and the mandrel 52 decreases with the movement of the piston 60, and fluid can escape to the borehole annulus 16 via an external port 63.
The packer 50A in FIG. 2A can have a double-piston arrangement as shown. In this case, a second piston 68 can also be moved by tubing pressure collecting in another piston chamber 64b via another flow port 54b. This second piston 68 also acts against the packing element 70 to extend it outward toward the surrounding borehole wall 15.
The packer 50B in FIG. 2B is similar to that discussed above with reference to FIG. 2A so that the same reference numerals are used between similar components. This packer 50B in FIG. 2B has a two-stage activation of the packing element 70. When tubing pressure is supplied down the mandrel's bore 53 and into the piston chamber 64, the pressure moves a first-stage setting mandrel 65 under the packing element 70 and increases the element's outer diameter.
Once the setting mandrel 65 fully extends between the packing element 70 and the mandrel 52 with the distal end of the mandrel 65 even reaching inside the fixed end ring 58, the second stage of the packer 50B is initiated as the piston 60 is now moved by the communicated pressure. The end 61 of the piston 60 compresses the packing element 70 against the fixed end ring 58, causing the element 70 to extend outward and seal against the borehole wall 15. As before, the body lock ring of the ratchet mechanism 66 locks the piston 60 into position so the packer 50B can hold differential pressure from above and below.
The hydraulic pistons 60 in the hydraulically-set packers 50A-50B, such discussed above and used in the fracture system 20 of FIG. 1, only apply setting force to the packing element 70 when there is tubing pressure in the packer mandrel 52 and no significant pressure in the uphole and downhole annuli surrounding the packer 50A-B.